BR112013013149B1 - CONNECTION JOINT FOR EXCENTRIC FLOW PATHWAYS TO CONCENTRIC FLOW PATHWAYS - Google Patents

Abstract

connection joint for eccentric flow paths to concentric flow paths. it is a well bore apparatus and a method comprising a first well bore tool having a flow path and at least a secondary flow path and a second well bore tool having a primary flow path and a secondary flow path. a radial center of the primary flow path in the first well bore tool is displaced from a radial center of the primary flow path in the second well bore tool which comprises a connecting joint that connects the first well bore tool to the second well hole tool having a primary flow path that fluidly connects the primary flow path of the first well hole tool to the primary flow path of the second well hole tool, and at least one secondary flow path that fluidly connects to at least one secondary flow path of the first well hole tool to at least one secondary flow path of the second well hole tool.

Description

REFERENCE TO CORRELATED DEPOSIT REQUESTS

[0001] This claim claims benefit to U.S. Provisional Application 61 / 424,427, filed on December 17, 2010 and U.S. Provisional Application 61 / 499,865, filed on June 22, 2011.

BACKGROUND OF THE INVENTION

[0002] This section is intended to introduce various aspects of the technique, which can be associated with exemplary modalities of the present description. This discussion is believed to assist in providing a framework to facilitate a better understanding of the aspects of this description. Consequently, it should be understood that this section should be read in this sense, and not necessarily as admissions to the prior art.

FIELD OF THE INVENTION

[0003] This description refers to the well completion field. More specifically, the present invention relates to the completion of well holes using sand sieves and gravel seals. The order also refers to a downhole tool that can be used to connect eccentric flow paths to concentric flow paths for installing a gravel seal.

DISCUSSION OF TECHNOLOGY

[0004] In drilling for oil and gas wells, a well bore is formed using a drill bit that is prompted downwards at a lower end of a drilling column. After drilling to a predetermined depth, the drill column and drill bit are removed and the well hole is coated with a coating column. Therefore, an annular area is formed between the coating column and the formation. Typically, a cementation operation is conducted in order to fill or “tighten” the annular area with cement. The combination of cement and coating strengthens the well bore and facilitates the isolation of the formation behind the coating.

[0005] It is common to place several columns of casing having progressively smaller external diameters in the well bore. The drilling process and then cementing of progressively smaller cement columns is repeated several times until the well has reached full depth. The final coating column, referred to as a production coating, is cemented into position and drilled. In some cases, the final coating column is a lining, that is, a coating column that is not related to the surface.

[0006] As part of the completion process, a wellhead is installed on the surface. The wellhead controls the flow of production fluids to the surface, or the injection of fluids into the wellbore. Fluid accumulation and processing equipment, such as tubes, valves and separators are also provided. Then, production operations can begin.

[0007] In some cases, a well bore is completed in a formation that is loose or "unconsolidated". This means that as production fluids are produced in the well bore, forming particles, for example, sand and fines, can also invade the well bore. These particles are harmful to production equipment. More specifically, the forming particles can be erosive to downhole pumps as well as tubes, valves, and surface fluid separation equipment.

[0008] The problem of unconsolidated formations can occur in connection with the completion of a coated well hole. In this case, the forming particles can invade the perforations created through the production coating and a surrounding cement layer. However, the problem of unconsolidated formations is much more pronounced when a well hole is formed as an “open hole” completion.

[0009] In an open pit completion, a production liner is not extended through the production zones and drilled; instead, the production zones are left uncoated, or “open”. A production column or “tubing” is then positioned inside the well hole extending down to the last casing column and through a subsurface formation.

[0010] There are certain advantages to open pit completions versus coated bore completions. First, due to the fact that open pit completions do not have perforated tunnels, forming fluids can converge in the well bore radially 360 degrees. This has the benefit of eliminating the additional pressure drop associated with converging radial flow and then linear flow through the particle-filled drilling tunnels. The reduced pressure drop associated with an open pit completion virtually guarantees that this is more productive than an unstimulated coated bore in the same formation. Second, open hole techniques are generally less expensive than coated hole completions.

[0011] A common problem in open pit completions is the immediate exposure of the borehole to the surrounding formation. If the formation is not consolidated or heavily sandy, the flow of production fluids into the well bore can carry formation particles with it, for example, sand and fines. These particles can be erosive to downhole production equipment and to tubes, valves and surface separation equipment.

[0012] To control the invasion of sand and other particles, sand control devices can be used. Sand control devices are generally installed at the bottom of the well through formations to retain solid materials larger than a certain diameter while allowing fluids to be produced. A sand control device typically includes an elongated tubular body, known as a base tube, having several notched openings. Then, the base tube is typically wrapped with a filtering medium, such as a screen or wire mesh.

[0013] For fortaceler sand control devices, particularly in open pit completions, it is common to install a gravel seal. Gravel sealing in a well involves placing gravel or other particulate matter around the sand control device after the sand control device is suspended or otherwise placed in the well bore. To install the gravel seal, a particulate material is distributed down the well by means of a carrier fluid. The carrier fluid with the gravel forms a gravel slurry. The slurry dries in place, leaving a circumferential gravel seal. The gravel not only assists in the filtration of particles, but also helps to maintain the integrity of the well bore. The use of gravel seals also eliminates the need for cementing, drilling, and post-drilling cleaning operations.

[0014] In a sealing completion with open pit gravel, the gravel is positioned between a sieve of sand that surrounds a perforated base tube and a wall surrounding the well hole. During production, the formation fluids flow from the underground formation, through the gravel, through the screen, and into the internal base tube. Therefore, the base tube serves as a part of the production column.

[0015] A problem historically found in gravel sealing is that an accidental loss of carrier fluid from the slurry during the distribution process can result in premature bridges of sand and gravel being formed at various locations along open hole intervals. For example, in an inclined production interval or in an interval having an enlarged or irregular hole, a weak gravel distribution can occur due to premature loss of carrier fluid from the gravel slurry in the formation. The premature sand bridge can block the flow of gravel slurry, causing gaps to be formed over the completion interval. Therefore, a complete gravel seal from the bottom up is not achieved, leaving the well hole exposed to the infiltration of sand and fines.

[0016] The sand bridge problem was addressed through the use of Alternate Path® Technology, or "APT." Alternate Path® fluid bypass technology employs bypass tubes (or taps) that allow the gravel slurry to bypass selected areas along a well bore. This fluid contouring technology is described, for example, in US Patent No. 5,588,487 entitled “Tool for Blocking Axial Flow in Gravel-Packed Well Annulus,” and in PCT Publication No. WO 2008/060479 entitled “Wellbore Method and Apparatus for Completion, Production, and Injection, ”each of which is incorporated herein in its entirety as a reference. Additional references that discuss fluid bypass technology include U.S. Patent No. 4,945,991; U.S. Patent No. 5,113,935; U.S. Patent No. 7,661,476; and M.D. Barry, et al, “Open-hole Gravel Packing with Zonal Isolation,” SPE Report No. 110,460 (November 2007).

[0017] It is known to use rectangular bypass tubes that are eccentrically attached to the outside of a sand sieve. The Schlumberger's OptiPac ™ fluid gravel sealing system is an example of a sand sieve having external bypass tubes and one or more external transport tubes. See also G. Hurst, et al., S. Tocalino, “Alternate Path Completions: A Critical Review and Lessons Learned From Case Histories With Recommended Practices for Deepwater Applications,” SPE Report No. 86.532 (2004). The eccentric layout reduces the overall diameter size of the tool compared to if the equivalent deviation tubes were fixed concentrically.

[0018] Recent technological advances have led to the development of two new downhole tools useful for installing a gravel seal. The first is an Alternate Path® sand sieve with concentric internal bypass tubes. The modalities of such a sand sieve are shown and described in M.T. Hecker, et al., “Extending Openhole Gravel-Packing Capability: Initial Field Installation of Internal Shunt Alternate Path Technology,” SPE Report No. 135,102 (2010); and in U.S. Patent Publication No. 2008/0142227 filed in 2008 and entitled “Wellbore Method and Apparatus for Completion, Production and Injection.” The second is a concentric internal bypass open hole plug. The modalities of this shutter are shown and described in co-pending US Provisional Patent Application No. 61 Z424,427 filed on December 17, 2010. This application is entitled “Packer for Alternate Path Gravel Packing, and Method for Completing a Wellbore. " The combination of these tools allows for true zonal isolation in gravel seal completions.

[0019] You want to be able to connect a first borehole tool (such as the OptiPac ™ sand sieve) that has eccentric flow paths, with a second borehole tool (such as a bypass screen) or an internal bypass open hole plug) that provides concentric flow paths. Alternatively, it is desirable to connect a first borehole tool (such as an Alternate Path® sand sieve having concentric internal bypass tubes) with a threadless tube or plug having eccentric flow paths and bypass tubes. Alternatively, it is desirable to connect to the sand sieve joints, where one joint has a concentric primary flow path, and the other has an eccentric primary flow path.

[0020] Several connectors have been described between concentric flow paths or between eccentric flow paths. Such connectors are at least mentioned, for example, in U.S. Patent No. 7,497,267; US 7,886,819; US 5,390,966; US 5,868,200; US 6,409,219; US 6,520,254; US 6,752,207; US 6,789,621; US 6,789,624; US 6,814,139; US 6,923,262; US 7,048,061; US 2008/0142227; US 7,661,476; US 7,828,056). They provide fluid communication between eccentric primary flow paths, between concentric primary flow paths, between eccentric secondary flow paths, or between concentric secondary flow paths. However, a connection tool that connects concentric flow paths to eccentric flow paths (or vice versa) between two screen joints or between a screen joint and a plug has not yet been developed.

[0021] Therefore, there is a need for an improved sand control system that uses a connection joint to connect an eccentric sand sieve to a concentric plug, or vice versa. There is an additional need for a connection tool that fluidly connects a first well hole tool having a primary flow path and at least a secondary flow path to a second well hole tool also having a primary flow path and at least one secondary flow path, wherein a radial center of the primary flow path in the first well hole tool is displaced from a radial center of the primary flow path in the second well hole tool.

SUMMARY OF THE INVENTION

[0022] Firstly, a sand control system is provided. The sand control system includes a first borehole tool having a primary flow path and at least a secondary flow path. The sand control system also includes a second well bore tool, with the second well bore tool also having a primary flow path and at least a secondary flow path. A radial center of the primary flow path in the first well hole tool is displaced from a radial center of the primary flow path in the second well hole tool.

[0023] The sand control system also has a connection joint. The connection joint connects the first well hole tool to the second well hole tool. The connection joint comprises a primary flow path that fluidly connects the primary flow path of the first well-hole tool to the primary flow path of the second well-hole tool. The connection joint also has at least one secondary flow path that fluidly connects to at least one secondary flow path of the first well hole tool to at least one secondary flow path of the second well hole tool.

[0024] In a preferred mode of the sand control system, the first borehole tool is a sand sieve. The sand sieve comprises an elongated base tube, a circumferentially filtering medium around the base tube, and at least one bypass tube along the base tube. The bypass tube serves as an alternating flow channel. In this sense, the bypass tube is configured to allow a gravel slurry to at least partially circumvent the first borehole tool when any premature sand bridge occurs in the surrounding annular region between the sand sieve and the borehole during a gravel sealing operation in the well hole. In this case, the base tube serves as the primary flow path of the sand sieve, and the at least one bypass tube serves as at least one secondary flow path of the sand sieve.

[0025] In the sand sieve, the elongated base tube is preferably eccentric to the sand sieve. Then, each at least one bypass tube can have a rounded profile, a square profile, or a rectangular profile.

[0026] In another preferred mode of the sand control system, the second well hole tool is a plug. The plug comprises an elongated inner mandrel, a sealing element external to the inner mandrel, and an annular space that serves as an alternating flow channel. The annular space is configured to allow the gravel slurry to at least partially circumvent the second well hole tool during a gravel sealing operation in a well hole after the plug has been placed in the well hole. In this case, the inner mandrel serves as the primary flow path of the plug, and the annular space serves as at least one secondary flow path of the plug.

[0027] In the obturator, the internal mandrel is preferably concentric to the obturator. In addition, the annular space resides between the inner mandrel and a surrounding piston shell. The plug also has one or more flow ports that provide fluid communication between the annular space and a pressure bearing surface of the piston shell.

[0028] In this document, a connection joint is also provided, which serves to connect a first well hole tool to a second well hole tool. The connection joint is configured according to the connection joint described above. The connecting joint can be used as part of a sand control system. However, the connection joint can be used to connect any two tubular tools having primary flow paths and secondary flow paths, in which a radial center of the primary flow path in the first borehole tool is displaced from a radial center DAE primary flow path in the second well bore tool.

[0029] In one embodiment, the primary flow path of the first well-hole tool is eccentric to the first well-hole tool, while the primary flow path of the second well-hole tool is concentric to the second well-hole tool. well. The first well-bore tool is preferably a sand sieve, while the second well-bore tool is preferably a mechanically adjusted plug.

[0030] A base tube serves as the primary flow path of the sand sieve, while an elongated internal mandrel serves as the primary flow path of the shutter. The secondary flow path for the sand sieve consists of bypass tubes that serve as alternative flow channels. The secondary flow path to the plug may consist of bypass tubes or be an annular space formed between the inner mandrel and a surrounding movable piston shell. Alternative flow channels allow a gravel slurry to bypass the sand sieve joint, connection joint, and plug even after the plug has been placed in the well hole.

[0031] The at least one secondary flow path of the connection joint changes the direction along a longitudinal geometric axis of the connection joint at least once. In one aspect, an internal diameter of the primary flow path of the connection joint is greater than an internal diameter (i) of the primary flow path of the first well-hole tool, (ii) of the primary flow path of the second drilling tool. well bore, or (iii) both.

[0032] Optionally, the connection joint can include an external protection cover.

[0033] This document also provides a method for completing a well hole in a subsurface formation. In one aspect, the method comprises providing a first borehole tool. The first borehole tool has a primary flow path and at least a secondary flow path. The method also includes providing a second well bore tool. The second well hole tool also has a primary flow path and at least a secondary flow path. A radial center of the primary flow path of the first well hole tool is displaced from a radial center of the primary flow path to the second well hole tool.

[0034] The method also includes providing a connection joint. The connection joint also comprises a primary flow path and a secondary flow path. Then, the method includes fluidly connecting the link joint to the first well hole tool at a first end, and fluidly connecting the link joint to the second well hole tool at a second end. In this way, the primary flow path of the first well hole tool is in fluid communication with the primary flow path of the second well hole tool. In addition, at least one secondary flow path of the first well hole tool is in fluid communication with at least one secondary flow path of the second well hole tool.

[0035] The method also includes inserting the connection joint and the first and second well hole tools connected in a well hole to a selected subsurface location. Then, the fluid is injected into an annular region between the connection joint and the surrounding well hole. The method then includes additionally injecting the fluid into the annular space and through the secondary flow paths of the first well bore tool, the connection joint, and the secondary flow paths of the second well bore tool.

[0036] The connection joint can be used to connect any two tubular tools having primary flow paths and secondary flow paths, in which a radial center of the primary flow path in the first well bore tool is displaced from a radial center of the primary flow path in the second well bore tool. However, it is preferred that the connection joint is used as part of a sand control system. In this case, the first wellbore tool is preferably a sand sieve, while the second wellbore tool is preferably an adjustable plug.

[0037] In one embodiment, the primary flow path of the first well-hole tool (such as the sand sieve) is eccentric to the first well-hole tool, while the primary flow path of the second well-hole tool (such as a plug) is concentric to the second well hole tool.

[0038] A base tube serves as the primary flow path of the sand sieve, while an elongated internal mandrel serves as the primary flow path of the shutter. The secondary flow path for the sand sieve consists of bypass tubes that serve as alternative flow channels. The secondary flow path to the plug can consist of bypass tubes or it can be an annular area formed between the inner mandrel and a surrounding movable piston shell. In any case, the alternative flow channels allow a gravel slurry to bypass the sand sieve joint, the connecting joint, and the plug, even after the plug has been placed in the well hole.

[0039] In one aspect, the method further comprises placing the plug in the borehole. In this case, the step of additionally injecting the fluid through the secondary flow paths is carried out after the plug has been placed.

[0040] In another aspect, the method also comprises inserting a seating tool in the internal mandrel of the plug, and then maneuvering the seating tool to mechanically move a release sleeve from a position held along the mandrel. internal shutter. This serves to release the piston shell for axial movement. The method then includes communicating the hydrostatic pressure to the piston shell through one or more flow ports, thereby moving the released piston shell axially and activating the sealing element against the surrounding borehole.

[0041] BRIEF DESCRIPTION OF THE DRAWINGS

[0042] In order that the present inventions can be better understood, certain illustrations, graphs and / or flowcharts are attached to it. However, it should be noted that the drawings illustrate only the selected modalities of the inventions and, therefore, should not be considered as limiting the scope, so that the inventions can admit other modalities and equally effective applications.

[0043] Figure 1 is a cross-sectional view of an illustrative well hole. The well hole was drilled through three different subsurface intervals, each interval under pressure of formation and containing fluids.

[0044] Figure 2 is an enlarged cross-sectional view of an open pit completion of the well bore in Figure 1. The completion of an open pit at the depth of the three subsurface intervals is seen more clearly.

[0045] Figure 3A is a cross-sectional side view of a plug assembly, in one embodiment. In this document, a base tube is shown, with surrounding plug elements. Two mechanically adjusted shutters are shown schematically, next to an intermediate expandable shutter element.

[0046] Figure 3B is a cross-sectional view of the plug assembly of Figure 3A, taken along lines 3B-3B of Figure 3A. The bypass tubes are seen inside the expandable plug element.

[0047] Figure 3C is a cross-sectional view of the plug assembly of Figure 3A, in an alternative embodiment. Instead of bypass tubes, transport tubes are seen connected around the base tube.

[0048] Figure 4A is a cross-sectional side view of the plug assembly of Figure 3A. In this document, the sand control devices, or sand sieves, have been placed at opposite ends of the shutter assembly. The sand control devices use external bypass tubes.

[0049] Figure 4B provides a cross-sectional view of the plug assembly of Figure 4A, taken along line 4B-4B of Figure 4A. The bypass tubes are seen outside the sand sieve to provide an alternative flow path for a particulate slurry.

[0050] Figure 5A is another cross-sectional side view of the plug assembly of Figure 3A. In this document, the sand control devices, or sand sieves, have been placed again at opposite ends of the plug assembly. However, sand control devices use internal bypass tubes.

[0051] Figure 5B provides a cross-sectional view of the plug assembly of Figure 5A, taken along line 5B-5B of Figure 5A. The bypass tubes are seen inside the sand sieve to provide an alternative flow path for a particulate slurry.

[0052] Figure 6A is a cross-sectional side view of one of the mechanically adjusted shutters of Figure 3A. The mechanically adjusted plug is in its insertion position.

[0053] Figure 6B is a cross-sectional side view of the mechanically adjusted plug of Figure 6A. In this document, the mechanically adjusted plug element is in its adjustment position.

[0054] Figure 6C is a cross-sectional view of the obturator mechanically adjusted to Figure 6A. The view is taken along line 6C-6C in Figure 6A.

[0055] Figure 6D is a cross-sectional view of the plug of Figure 6A. The view is taken along line 6D-6D of Figure 6B.

[0056] Figure 6E is a cross-sectional view of the plug of Figure 6A. The view is taken along line 6E-6E of Figure 6A.

[0057] Figure 6F is a cross-sectional view of the shutter mechanically adjusted ad Figure 6A. The view is taken along line 6F-6F in Figure 6B.

[0058] Figure 7A is an enlarged view of the release key in Figure 6A. The release key is in its insertion position along the internal chuck. The shear pin has not yet been sheared.

[0059] Figure 7B is an enlarged view of the release key in Figure 6B. The shear pin was sheared, and the release key was removed from the internal mandrel.

[0060] Figure 7C is a perspective view of a seating tool as it can be used to attach to a release sleeve, and thus to shear a shear pin into the release key.

[0061] Figures 8A to 8C demonstrate several eccentric designs for a well bore tool. In this document, borehole tools are sand sieves or threadless tubes. Each of these sand sieves or illustrative threadless tubes comprises a base tube, with one or more alternative eccentric flow channels around it providing secondary flow paths.

[0062] Figures 9A to 9C demonstrate several concentric designs for a well bore tool. In this document, well-hole tools are shutters. Each of the illustrative shutters comprises a base tube, with alternative flow channels concentric around it providing secondary flow paths.

[0063] Figure 10A provides a cross-sectional side view of a connection joint to connect internal base tubes of two tubular bodies, and provide fluid communication between the eccentric and concentric secondary flow paths. The connection joint operates to fluidly connect a first well bore tool to a second well bore tool.

[0064] Figure 10B is a first cross-sectional view, taken along line B-B of Figure 10A. The cut is taken at the first end of the connection joint.

[0065] Figure 10C is a second cross-sectional view, taken along line C-C of Figure 10A. The cut is taken at a second opposite end of the connection joint.

[0066] Figure 11A is a Cartesian graph representing the displacement of the geometric axis (first geometric axis y) in relation to the symmetrical length of a connection joint (geometric axis x) for a connection joint of 4.88 meters (16 foot). Figure 11A also represents a curvature (second y-axis) in relation to the symmetrical length of a connection joint (geometric axis x) for the 4.88 meter (16 foot) connection joint.

[0067] Figure 11 B is a Cartesian graph representing the displacement of the geometric axis (first geometric axis y) in relation to the symmetrical length of a connection joint (geometric axis x) for a connection joint of 2.44 meters ( 8 feet). Figure 11 B also represents a curvature (second y axis) in relation to the symmetrical length of a connecting joint (geometric axis x) for the connecting joint 2.44 meters (8 feet).

[0068] Figure 11 C is a Cartesian graph that represents the displacement of the geometric axis (geometric axis y) in relation to the symmetrical length of a connection joint (geometric axis x) for a connection joint of 2.44 meters (8 foot). In the present document, the graph compares a connection joint having a curved profile with a connection joint having straight segments.

[0069] Figure 12 is a flowchart that shows the steps for a method of completing a well bore in a subsurface formation, in one modality.

[0070] Figure 13 is another flow chart. Figure 13 shows the steps for a method of placing a plug in a borehole, in one embodiment.

DETAILED DESCRIPTION OF CERTAIN MODALITIES

[0071] Definitions

[0072] Depending on the use in question, the term "hydrocarbon" refers to an organic compound that includes primarily, if not exclusively, the elements hydrogen and carbon. In general, hydrocarbons are divided into two classes: aliphatic, or straight chain hydrocarbons, and cyclic, or closed ring hydrocarbons, including cyclic terpenes. Examples of hydrocarbon-containing materials include any form of natural gas, oil, coal, and bitumen that can be used as a fuel or enhanced in a fuel.

[0073] Depending on the use in question, the term "hydrocarbon fluids" refers to a hydrocarbon or mixtures of hydrocarbons that are gaseous or liquid. For example, hydrocarbon fluids can include a hydrocarbon or hydrocarbon mixtures that are gaseous or liquid under formation conditions, processing conditions or ambient conditions (15 ° C and 1 atm of pressure). Hydrocarbon fluids can include, for example, petroleum, natural gas, coal bed methane, shale oil, pyrolysis oil, pyrolysis gas, a coal pyrolysis product, and other hydrocarbons that are in a gaseous or liquid.

[0074] Depending on the use in question, the term "fluid" refers to gases, liquids, and combinations of gases and liquids, as well as combinations of gases and solids, and combinations of liquids and solids.

[0075] Depending on the usage in question, the term "subsurface" refers to the geological stratum that occurs below the earth's surface.

[0076] The term "subsurface gap" refers to a formation or a portion of a formation in which formation fluids may be present. The fluids can be, for example, hydrocarbon liquids, hydrocarbon gases, aqueous fluids, or combinations thereof.

[0077] Depending on the use in question, the term “well hole” refers to a hole in the subsurface made by drilling or inserting a conduit in the subsurface. A well hole can have a substantially circular cross section, or other cross-sectional shape. Depending on the use in question, the term “well”, when referring to an opening in the formation, can be used interchangeably with the term “well hole”.

[0078] The term “tubular member” refers to any tube, such as a lining joint, a portion of a lining, or a short tube (from the English, “pup joint”).

[0079] The term "sand control device" means any elongated tubular body that allows an influx of fluid into an internal hole or a base tube while filtering out predetermined amounts of sand, fines and granular debris from a surrounding formation. A sand sieve is an example of a sand control device.

[0080] The term "alternative flow channels" means any collection of piping and / or bypass tubes that provide fluid communication through or around a plug to allow a gravel slurry to bypass the plug elements or any bridge of premature sand in the annular region, and continue the fence with gravel pit below. The term “alternative flow channels” can also mean any collection of piping and / or bypass tubes that provide fluid communication through or around a sand sieve or a threadless tube (with or without an external protective cover) to allow a gravel slurry to bypass any premature sand bridge in the annular region and continue the gravel seal below, or above and below, the downhole tool.

[0081] Description of Specific Modalities

[0082] Inventions are described according to certain specific modalities. However, to the extent that the detailed description below is specific to a particular modality or to a particular use, it is intended to be illustrative only and should not be construed as limiting the scope of the inventions.

[0083] Certain aspects of the inventions are also described according to various figures. In certain figures, the top of the drawing page is intended to be towards the surface, and the bottom of the drawing page towards the bottom of the well. Although wells are commonly completed in a substantially vertical orientation, it is understood that the wells can also be tilted and / or even less horizontally completed. When the descriptive terms "up and down" or "upper" and "lower" or similar terms are used in reference to a drawing or in the claims, they are intended to indicate a relative location on the drawing page or in relation to the terms of the claim, and not necessarily the orientation in the ground, since the present inventions are useful no matter how the borehole is oriented.

[0084] Figure 1 is a cross-sectional view of an illustrative well hole 100. Well hole 100 defines a hole 105 that extends from a surface 101, and in the subsurface of the earth 110. The well hole 100 is completed to have an open orifice portion 120 at a lower end of well hole 100. Well hole 100 was formed for the purpose of producing hydrocarbons for commercial sales. A production pipe column 130 is provided in bore 105 to transport production fluids from the open orifice portion 120 to surface 101.

[0085] Well hole 100 includes a well tree, shown schematically at 124. Well tree 124 includes a containment valve 126. Containment valve 126 controls the flow of production fluids from the well hole. well 100. In addition, a subsurface safety valve 132 is provided to block the flow of fluids from the production line 130 in the event of a rupture or catastrophic event above the subsurface safety valve 132. Well hole 100 may have optionally a pump (not shown) inside or just above open orifice portion 120 to artificially suspend production fluids from open orifice portion 120 to well shaft 124.

[0086] Well hole 100 has been completed by placing a series of tubes on subsurface 110. These tubes include a first coating column 102, sometimes known as a surface column or a conductor. These tubes also include at least a second 104 and a third lining column 106. These casing columns 104, 106 are intermediate casing columns that provide support for the well hole 100 walls. The intermediate casing columns 104, 106 can be suspended from the surface, or can be suspended from a next column. top coat using an expandable liner or liner support. It is understood that a tube column that does not extend back to the surface (such as a coating column 106) is commonly referred to as a "liner."

[0087] In the well hole illustrative arrangement of Figure 1, the intermediate coating column 104 is suspended from the surface 101, while the coating column 106 is suspended from a lower end of the coating column 104. employ additional intermediate casing columns (not shown). The present inventions are not limited to the type of coating arrangement used.

[0088] Each coating column 102, 104, 106 is placed in position by cement 108. Cement 108 isolates the various formations of subsurface 110 from well bore 100 and between them. The cement 108 extends from the surface 101 to a depth "L" at a lower end of the coating column 106. It is understood that some intermediate coating columns may not be completely cemented.

[0089] An annular region 204 is formed between the production pipe 130 and the casing column 106. A production plug 206 seals the annular region 204 near the lower end "L" of the casing column 106.

[0090] In many well holes, a final coating column known as the production coating is cemented to a depth where subsurface production intervals are present. However, illustrative well hole 100 is completed as an open well hole. Consequently, well hole 100 does not include a final coating column along open hole portion 120.

[0091] In the illustrative well bore 100, the open hole portion 120 crosses three different subsurface intervals. These are indicated as upper range 112, intermediate range 114, and lower range 116. Upper range 112 and lower range 116 may, for example, contain valuable oil deposits sought to be produced, while intermediate range 114 may contain primarily water or another aqueous fluid within its pore volume. This can occur due to the presence of native water zones, tendencies of high permeability or natural fractures in the aquifer, or the formation of escape channels from the injection wells. In this case, there is a likelihood that water will invade well 100.

[0092] Alternatively, the upper 112 and intermediate 114 ranges may contain hydrocarbon fluids intended to be produced, processed and sold, while the lower range 116 may contain oil along with ever-increasing amounts of water. This can occur due to winding, which consists of an elevation of contact between hydrocarbon and water near the well. In this case, there is again the possibility that water will invade well 100.

Alternatively, the upper 112 and lower 116 ranges may be producing hydrocarbon fluids from a sandy matrix or other permeable rock matrix, while the intermediate interval 114 may represent a non-permeable shale or, otherwise , be substantially impervious to fluids.

[0094] In any of these cases, it is desirable that the operator isolate the selected intervals. In the first case, the operator will want to isolate the intermediate range 114 from the production column 130 and the upper ranges 112 and lower 116 so that, primarily, hydrocarbon fluids can be produced through the well bore 100 and the surface 101 In the second case, the operator will eventually want to isolate the lower range 116 from the production column 130 and the upper ranges 112 and intermediate 114 so that, primarily, hydrocarbon fluids can be produced through well bore 100 and at the surface 101. In the third case, the operator will want to isolate the upper range 112 from the lower range 116, but does not need to isolate the intermediate range 114. Solutions to these needs in the context of an open pit completion are provided in this document, and demonstrated more comprehensively according to the procedure drawings.

[0095] According to the production of hydrocarbon fluids from a well bore having an open well completion, it is not only desirable to isolate the selected ranges, but also to limit the influx of sand and other fine particles. In order to avoid the migration of formation particles in the production column 130 during operation, the sand control devices 200 have been inserted into the well bore 100. These will be more fully described below according to Figure 2.

[0096] Referring now to Figure 2, sand control devices 200 contain an elongated tubular body referred to as base tube 205. Base tube 205 typically consists of a plurality of tube joints. The base tube 205 (or each tube joint that constitutes the base tube 205) typically has small perforations or slits to allow influx of production fluids.

[0097] Sand control devices 200 also contain a filter medium 207 wrapped or otherwise placed radially around the base tubes 205. The filter medium 207 can be a wire mesh or wire wrapper fitted around the base tube 205. Alternatively, the filtration medium of the sand sieve comprises a membrane screen, an expandable screen, a sintered metal screen, a porous medium made of polymer with a format memory, a porous medium sealed with fibrous material, or a bed of pre-sealed solid particles. Filter medium 207 prevents the influx of sand or other particles above a predetermined size into the base pipe 205 and the production pipe 130.

[0098] In addition to sand control devices 200, well hole 100 includes one or more plug assemblies 210. In the illustrative arrangement of Figures 1 and 2, well hole 100 has an upper plug assembly 210 'and a 210 ”lower plug assembly. However, additional shutter assemblies 210 or just one shutter assembly 210 can be used. The plug assemblies 210 ', 210 ”are exclusively configured to seal an annular region (seen at 202 of Figure 2) between the various sand control devices 200 and a wall 201 of the open hole portion 120 of the well hole 100 .

[0099] The plug assemblies 210 ', 210 "allow the operator to isolate selected intervals along the open orifice portion of the borehole 100 in order to control the migration of forming fluids. For example, in connection with the production of condensable hydrocarbons, water sometimes invades an interval. This may occur due to the presence of native water zones, winding (increased contact between hydrocarbon and water near the well), tendencies of high permeability, natural fractures, or the formation of escape channels from the injection wells. Depending on the mechanism or reason for the production of water, water can be produced at different locations and times during the life of a well. Similarly, a gas cap above an oil reservoir can expand and penetrate, causing oil to produce gas. Gas penetration reduces the conduction of the gas drive cap and suppresses oil production. Zonal annular isolation may also be desired for production allocation, production / injection fluid profile control, selective stimulation, or water or gas control.

[00100] Figure 2 is an enlarged cross-sectional view of the open hole portion 120 of the well hole 100 of Figure 1. The open hole portion 120 and the three gaps 112, 114, 116 are seen more clearly. The upper 210 'and lower 210 ”plug assemblies are also more clearly visible near the upper and lower limits of the intermediate range 114, respectively. Finally, the sand control devices 200 next to each of the intervals 112, 114, 116 are shown.

[00101] Referring to the shutter assemblies themselves, each 210 ', 210 ”shutter assembly can have at least two shutters. The two shutters are preferably adjusted through a combination of mechanical manipulation and hydraulic forces. The plug assemblies 210 represent an upper plug 212 and a lower plug 214. Each plug 212, 214 has an expandable portion or element made from an elastomeric material or a thermoplastic material capable of providing at least a temporary fluid seal to the borehole wall surrounding 201.

[00102] The elements for the upper 212 and lower 214 shutters must be able to withstand the pressures and loads associated with a gravel sealing process. Typically, these pressures range from about 2,000 psi to 3,000 psi. The shutter elements 212, 214 must also withstand a pressure load due to the differential pressures between the borehole and / or reservoir caused by natural failures, depletion, production, or injection. Production operations may involve selective production or production allocation to satisfy regulatory requirements. Injection operations may involve a selective fluid injection for strategic maintenance of the reservoir pressure. Injection operations can also involve a selective stimulus in acid fracture, matrix acidification, or removal of formation damage.

[00103] The surface or sealing elements for the mechanically adjusted shutters 212, 214 need only be in the order of inches to affect a suitable hydraulic seal. In one aspect, the elements are about 6 inches (15.2 cm) to about 24 inches (61.0 cm) long.

[00104] The elements for the shutters 212, 214 are preferably cupular elements. Cupular elements are known for use in coated hole completions. However, they are not generally known for use in open pit completions as they are not designed to expand in engagement with an open bore diameter. Furthermore, such expandable cupular elements may not maintain the required pressure differential found throughout the life of production operations, resulting in reduced functionality.

[00105] It is preferable that the shutters 212, 214 are able to expand to at least an outer diameter surface of 11 inches (about 28 cm), with an ovality ratio not greater than 1.1. The shutter elements 212, 214 should preferably be able to deal with erosion in an open hole section 120 of 8-1 / 2 inch (about 21.6 cm) or 9-7 / 8 inch (about 25.1 cm). The preferred cupular nature of the expandable portions of the plug elements 212, 214 will assist in maintaining at least one temporary seal against the wall 201 of the intermediate gap 114 (or other gap) as the pressure increases during the gravel sealing operation.

[00106] In one modality, cupular elements need not be liquid-tight, nor should they be evaluated to handle multiple pressure and temperature cycles. Cupular elements need only be designed for single use, that is, during the gravel sealing process of an open pit hole completion. This is because an intermediate expandable plug element 216 is also preferably provided for a long-term seal.

[00107] The top 212 and bottom 214 shutters are adjusted before a gravel sealing installation process. As more fully described below, the plug 212, 214 can be adjusted by mechanically shearing a shear pin and sliding a release sleeve. In turn, this releases a release key, which then allows a hydrostatic pressure to act downwardly against a piston housing. The piston shell moves downward along an inner mandrel (not shown), and then acts on both a centralizer and the plug elements along the inner mandrel. The centralizer and plug elements expand against the well bore wall 201. The expandable portions of the upper 212 and lower 214 shutters are expanded in contact with the surrounding wall 201 in order to frame the annular region 202 at a depth selected at the completion of open pit 120.

[00108] As a "support" to the cupular plug elements within the top 212 and bottom 214 plug elements, the plug assemblies 210 ', 210 "also include an intermediate plug element 216. The intermediate plug element 216 defines a elastomeric expansion material made from synthetic rubber compounds. Suitable examples of expandable materials can be found in CONSTRICTOR ™ or SWELLPACKER ™ from Easy Well Solutions, and in E-ZIP ™ from Swellfix. The expandable plug 216 can include an expandable polymer or an expandable polymeric material, which is known to those skilled in the art and which can be adjusted by one between a conditioned drilling fluid, a completion fluid, a production fluid, a injection, a stimulus fluid, or any combination of these.

[00109] The expandable plug element 216 is preferably attached to the outer surface of mandrel 215. The expandable plug element 216 is allowed to expand over time when in contact with hydrocarbon fluids, forming water, or any chemical described earlier that can be used as an actuator fluid. As the plug element 216 expands, it forms a fluid seal with the surrounding area, for example, the gap 114. In one aspect, a sealing surface of the expandable sealing element 216 is about 5 feet (1 , 5 meters) to 50 feet (15.2 meters) in length; and, more preferably, about 3 feet (0.9 meters) to 40 feet (12.2 meters) in length.

[00110] The expandable plug element 216 must be able to expand to the wellbore wall 201 and provide the pressure integrity required in such an expansion ratio. Since expandable shutters are typically placed in a shale section that may not produce hydrocarbon fluids, it is preferable to have a swelling elastomer or other material that can swell in the presence of forming water or an aqueous-based fluid. Examples of materials that will swell in the presence of an aqueous-based fluid are bentonite clay and a nitrile-based polymer with incorporated water absorbent particles.

[00111] Alternatively, the expandable plug element 216 can be manufactured from a combination of materials that expand in the presence of water and oil, respectively. Otherwise, the expandable plug element 216 can include two types of expansion elastomers - one for water and one for oil. In this situation, the water-swellable element will swell when exposed to water-based gravel sealing fluid or in contact with forming water, and the petroleum-based element will expand when exposed to hydrocarbon production. An example of an elastomeric material that will swell in the presence of a hydrocarbon liquid is the oleophilic polymer that absorbs hydrocarbons in its matrix. Expansion occurs from the absorption of hydrocarbons, which also lubricate and reduce the mechanical strength of the polymer chain as it expands. Ethylene propylene diene monomer rubber (class M), or EPDM, is an example of such a material.

[00112] The expandable plug 216 can be manufactured from another expandable material. An example is a polymer with format memory. U.S. Patent No. 7,243,732 and U.S. Patent No. 7,392,852 describe the use of such material for zonal isolation.

[00113] The mechanically adjusted plug elements 212, 214 are preferably fitted in a sealing fluid with water-based gravel that would be deflected around the expandable plug element 216, such as through bypass tubes (not shown in Figure 2). If only one hydrocarbon swelling elastomer is used, expansion of the element may not occur until a failure of any of the mechanically adjusted plug elements 212, 214.

[00114] The upper shutters 212 and lower 214 are generally mirror images of each other, except for the release sleeves that shear the respective shear pins or other coupling mechanisms. A unilateral movement of a displacement tool (shown and discussed according to Figures 7A and 7B) will allow shutters 212, 214 to be activated in sequence and simultaneously. The lower plug 214 is activated first, followed by the upper plug 212 as the displacement tool is pushed upward through an internal mandrel (shown and discussed according to Figures 6A and 6B). Preferably, a short spacing between the upper 212 and lower 214 shutters is provided.

[00115] Shutter assemblies 210 ', 210 ”help to control and manage fluids produced from different zones. In this sense, the plug assemblies 210 ', 210 ”allow the operator to seal a production or injection interval, depending on the well function. The installation of plug assemblies 210 ', 210 ”at initial completion allows an operator to interrupt the production of one or more zones during the life of the well in order to limit the production of water or, in some cases, of a fluid not - undesirable condensable, such as hydrogen sulfide.

[00116] Historically, shutters have not been installed when an open hole gravel seal is used because of the difficulty of forming a complete gravel seal above and below the plug. For example, see patent applications entitled “Wellbore Method and Apparatus for Completion, Production and Injection.” Applications published on August 16, 2007, as WO 2007/092082 and WO 2007/092083, respectively. The orders describe apparatus and methods for sealing with gravel from an open pit hole. PCT Publications Nos. WO 2007/092082 and WO 2007/092083 are hereby incorporated by reference in their entirety.

[00117] Certain technical challenges remained in relation to the methods described in the built-in PCT applications, particularly according to the shutter. Orders declare that the plug can be a hydraulically actuated inflatable element. This inflatable element can be manufactured from an elastomeric material or a thermoplastic material. However, designing a plug element from such materials requires that the plug element meets a particularly high level of performance. In this sense, the obturator element needs to be able to maintain zonal insulation over a period of years in the presence of high pressures and / or high temperatures and / or acidic fluids. As an alternative, orders declare that the plug can be an expansion rubber element that expands in the presence of hydrocarbons, water, or other stimuli. However, known swelling elastomers typically require about 30 days or more to fully expand in the sealed fluid engagement with the surrounding rock formation. Therefore, the improved shutters and the zonal isolation apparatus are offered in this document.

[00118] Figure 3A shows an illustrative plug assembly 300 that provides an alternative flow path for a gravel slurry. The shutter assembly 300 is seen in a cross-sectional side view. The plug assembly 300 includes several components that can be used to seal an annular space along the open hole portion 120.

[00119] First, the plug assembly 300 includes a main body section 302. The main body section 302 is preferably manufactured from steel or steel alloys. The main body section 302 is configured to have a specific length 316, such as about 40 feet (12.2 meters). The main body section 302 comprises individual pipe joints that will be between 10 feet (3.0 meters) and 50 feet (15.2 meters) in length. Typically, pipe joints are threaded end-to-end to form main body section 302 according to length 316.

[00120] The shutter assembly 300 also includes opposing mechanically adjusted shutters 304. The mechanically adjusted shutters 304 are shown schematically, and are generally in accordance with the mechanically adjusted shutter elements 212 and 214 of Figure 2. Preferably, the shutters 304 include cupular elastomeric elements less than 1 foot (0.3 meters) long. As described below, the shutters 304 have alternative flow channels that exclusively allow the shutters 304 to be adjusted before a gravel slurry is circulated in the well bore.

[00121] Optionally, the plug assembly 300 also includes an expandable plug 308. The expandable plug 308 conforms to the expandable plug element 216 of Figure 2. The expandable plug 308 is preferably about 3 feet (0 , 9 meters) to 40 feet (12.2 meters) in length. Together, the mechanically adjusted shutters 304 and the intermediate expandable plug 308 surround the main body section 302. Alternatively, a short spacing can be provided between the mechanically adjusted shutters 304 instead of the expandable plug 308.

[00122] The plug assembly 300 also includes a plurality of bypass tubes. Bypass tubes are viewed in spectrum at 318. Bypass tubes 318 can also be referred to as transport tubes or bridge tubes. Bypass tubes 318 are threadless tube sections having a length that extends along the length 316 of mechanically adjusted shutters 304 and expandable plug 308. Bypass tubes 318 in plug assembly 300 are configured to mate and form a seal with the bypass tubes in connected sand sieves as discussed below.

[00123] Bypass tubes 318 provide an alternative flow path through mechanically adjusted shutters 304 and intermediate expandable plug 308 (or spacing). This allows the bypass tubes 318 to carry a carrier fluid along the gravel to different intervals 112, 114 and 116 of the open orifice portion 120 of the well hole 100.

[00124] The shutter assembly 300 also includes connection members. These can represent traditional threaded couplings. First, a neck section 306 is provided at a first end of the plug assembly 300. The neck section 306 has external threads to connect to a threaded coupling box of a sand sieve or other pipe. Then, a notched or external threaded section 310 is provided at an opposite opposite end. The threaded section 310 serves as a coupling box for receiving an outer threaded end of a sand sieve or other tubular member.

[00125] The neck section 306 and the threaded section 310 can be made of steel or steel alloys. The neck section 306 and the threaded section 310 are configured to have a specific length 314, such as 4 inches (10.2 cm) to 4 feet (1.2 meters) (or other suitable distance). The neck section 306 and the threaded section 310 also have specific internal and external diameters. The neck section 306 has external threads 307, while the threaded section 310 has internal threads 311. These threads 307 and 311 can be used to form a seal between the plug assembly 300 and the sand control devices or other pipe segments .

[00126] A cross-sectional view of the plug assembly 300 is shown in Figure 3B. Figure 3B is taken along line 3B-3B in Figure 3A. In Figure 3B, the expandable plug 308 is seen circumferentially arranged around the base tube 302. Several bypass tubes 318 are placed radially and equidistant around the base tube 302. A central hole 305 is shown inside the base tube 302 Central hole 305 receives production fluids during production operations and transports them to production piping 130.

[00127] Figure 4A shows a side view in cross section of a zonal isolation device 400, in one embodiment. The zonal isolation apparatus 400 includes the plug assembly 300 of Figure 3A. In addition, the sand control devices 200 have been connected at opposite ends to the neck section 306 and the notched section 310, respectively. Bypass tubes 318 of plug assembly 300 are seen connected to bypass tubes 218 in sand control devices 200. Selective bypass tubes 218 in sand control devices 200 include ports or nozzles or holes 209, and such Bypass tubes are referred to as sealing tubes, to allow a flow of gravel slurry between an annular space of the well hole and the sealing tubes. Bypass tubes 218 in sand control devices 200 can optionally include valves at 209 to control the flow of gravel slurry, as well as sealing tubes (not shown).

[00128] Figure 4B provides a side cross-sectional view of the zonal isolation device 400. Figure 4B is taken along line 4B-4B of Figure 4A. This is cut through one of the sand sieves 200. In Figure 4B, the carved or perforated base tube 205 is seen. This is in accordance with base tube 205 of Figures 1 and 2. The central hole 105 is shown inside the base tube 205 to receive production fluids during production operations.

[00129] An outer mesh 220 is disposed immediately around the base tube 205. Preferably, the outer mesh 220 comprises a wire mesh or helically wound threads around the base tube 205, and serves as a screen. In addition, bypass tubes 218 are placed radially and equidistant around outer mesh 205. This means that sand control devices 200 provide an external modality for bypass tubes 218 (or alternative flow channels).

[00130] The configuration of the bypass tubes 218 is preferably concentric. This is seen in the cross-sectional view of Figure 3B. However, bypass tubes 218 can be eccentrically designed. For example, Figure 2B in US Patent No. 7,661,476 shows an "Antenna Technique" arrangement for a sand control device in which sealing tubes 208a and transport tubes 208b are placed external to the base tube 202 and the surrounding filter medium 204.

[00131] A concentric sand sieve flow channel comprises a central hole that receives the production fluids, and a filtration medium concentrically disposed around the central hole. In addition, two or more bypass tubes are placed radially around the central hole. An eccentric flow channel screen also comprises a central hole that receives the production fluids, but with a filter medium arranged eccentrically around the central hole. Two or more bypass tubes are placed adjacent to the central hole, typically outside both the central hole and the filtration medium. An external cover can be placed around the bypass tubes that represent the sealing tubes and the transport tubes.

[00132] In the arrangement of Figures 4A and 4B, the bypass tubes 218 are external to the filter medium, or to the external mesh 220. However, the configuration of the sand control device 200 can be modified. In this sense, the bypass tubes 218 can be moved internally to the filter medium 220.

[00133] Figure 5A shows a side view in cross section of a zonal isolation device 500, in an alternative mode. In this embodiment, the sand control devices 200 are again connected at opposite ends to the neck section 306 and the notched section 310, respectively, of the plug assembly 300. In addition, the bypass tubes 318 in the plug assembly 300 are seen connected to bypass tubes 218 in sand control assembly 200. However, in Figure 5A, sand control assembly 200 uses internal bypass tubes 218, meaning that bypass tubes 218 are disposed between base tube 205 and the surrounding filter means 220.

[00134] Figure 5B provides a side cross-sectional view of the zonal isolation apparatus 500. Figure 5B is taken along line B-B of Figure 5A. This is cut through one of the sand sieves 200. In Figure 5B, the carved or perforated base tube 205 is seen again. This is in accordance with base tube 205 of Figures 1 and 2. The central hole 105 is shown inside the base tube 205 to receive production fluids during production operations.

[00135] The bypass tubes 218 are placed radially and equidistant around the base tube 205. The bypass tubes 218 reside immediately around the base tube 205, and within a surrounding filter medium 220. This means that the sand control devices 200 of Figures 5A and 5B provide an internal modality for the bypass tubes 218.

[00136] An annular region 225 is created between the base tube 205 and the surrounding outer mesh or filter medium 220. The annular region 225 accommodates the influx of production fluids into a well bore. External wire winder 220 is supported by a plurality of support ribs extending radially 222. Ribs 222 extend through annular region 225.

[00137] Figures 4A and 5A have provisions for connecting the sand control joints to a shutter assembly. The bypass tubes 318 (or alternative flow channels) within the shutters fluidly connect to the bypass tubes 218 along the sand sieves 200. However, the zonal isolation device provisions 400, 500 of Figures 4A-4B and 5A-5B are illustrative only. In an alternative arrangement, a piping system can be used to provide fluid communication between bypass tubes 218 and bypass tubes 318.

[00138] Figure 3C is a cross-sectional view of the plug assembly 300 of Figure 3A, in an alternative embodiment. In this arrangement, the bypass tubes 218 are connected around the base tube 302. A support ring 315 is provided around the bypass tubes 318. The walls 222 separate the bypass tubes 318 within the expandable plug element 308. Again, it is understood that the apparatus and methods are not confined by the particular design and arrangement of the bypass tubes 318 the slurry contour is provided for the plug assembly 210. However, it is preferred that a concentric arrangement be maid.

[00139] It should also be noted that the coupling mechanism for the sand control devices 200 with the shutter assembly 300 may include a sealing mechanism (not shown). The sealing mechanism prevents leakage of slurry that is in the alternating flow path formed by the bypass tubes. Examples of such sealing mechanisms are described in U.S. Patent No. 6,464,261; in International Patent Application Publication No. WO 2004/094769; in International Patent Application Publication No. WO 2005/031 105; in U.S. Order Publication No. 2004/0140089; U.S. Order Publication No. 2005/0028977; in U.S. Order Publication No. 2005/0061501; and U.S. Order Publication No. 2005/0082060.

[00140] As noted, the obturator assembly 300 includes a pair of mechanically adjusted obturators 304. When using the obturator assembly 300, the obturators 304 are beneficially adjusted before the slurry is injected and the gravel seal is formed. This requires a unique shutter arrangement where the bypass tubes are provided for an alternating flow channel.

[00141] The plugs 304 of Figure 3A are shown schematically. However, Figures 6A and 6B provide more detailed views of a mechanically adjusted plug 600 that can be used in the plug assembly of Figure 3A, in one embodiment. The views in Figures 6A and 6B provide lateral cross-sectional views. In Figure 6A, the shutter 600 is in its insertion position, while in Figure 6B the shutter 600 is in its adjusted position.

[00142] Other modalities of sand control devices 200 can be used with the apparatus and methods of this document. For example, sand control devices can include independent screens (SAS), pre-sealed screens, or membrane screens. The joints can be any combination of mesh, pipe without threads, or zonal insulation device.

[00143] First, the plug 600 includes an inner mandrel 610. The inner mandrel 610 defines an elongated tubular body that forms a central hole 605. Central hole 605 provides a primary flow path for production fluids through plug 600. After Upon installation and the start of production, central hole 605 carries production fluids to hole 105 of sand sieves 200 (seen in Figures 4A and 4B) and production pipe 130 (seen in Figures 1 and 2).

[00144] The plug 600 also includes a first end 602. Threads 604 are placed along inner mandrel 610 at first end 602. Illustrative threads 604 are external threads. A housing connector 614 having internal threads at both ends or threaded into threads 604 at the first end 602. The first end 602 of inner mandrel 610 with housing connector 614 is referred to as the housing end. The second end (not shown) of the internal mandrel 610 has external threads and is referred to as the pin end. The pin end (not shown) of the internal mandrel 610 allows the plug 600 to be connected to the box end of a sand sieve or other tubular body, such as an independent screen, a capture module, a production pipe, or a pipe without threads.

[00145] The housing connector 614 at the housing end 602 allows the plug 600 to be connected to the pin end of a sand sieve or other tubular body, such as an independent screen, a capture module, a production pipe, or a pipe without threads.

[00146] The internal mandrel 610 extends along the length of the plug 600. The internal mandrel 610 can be composed of multiple connected segments, or together. The inner mandrel 610 has a slightly smaller inner diameter near the first end 602. This is due to a seating shoulder 606 machined in the inner mandrel. As explained in more detail below, seating shoulder 606 captures a release sleeve 710 in response to the mechanical force applied by a seating tool.

[00147] The plug 600 also includes a piston mandrel 620. The piston mandrel 620 extends generically from the first end 602 of the plug 600. The piston mandrel 620 can be composed of multiple connected segments, or joints. The piston mandrel 620 defines an elongated tubular body that resides circumferentially substantially concentric to the inner mandrel 610. An annular space 625 is formed between the inner mandrel 610 and the surrounding piston mandrel 620. The annular space 625 beneficially provides a path secondary flow or alternative flow channels for fluids.

[00148] In the arrangement of Figures 6A and 6B, the alternative flow channels defined by the annular space 625 are external to the internal mandrel 610. However, the plug could be reconfigured in such a way that the alternative flow channels were inside the bore 605 of the internal mandrel 610. In any case, the alternative flow channels are “along” the internal mandrel 610.

[00149] The annular space 625 is in fluid communication with the secondary flow path of another downhole tool (not shown in Figures 6A and 6B). Such a separate tool can be, for example, sand sieves 200 of Figures 4A and 5A, or a threadless tube, an expandable zonal isolation plug, such as plug 308 of Figure 3A, or another tubular body. The tubular body may or may not have alternative flow channels.

[00150] The plug 600 also includes a 630 coupling. The 630 coupling is connected and sealed (for example, through “o” elastomeric rings) to the piston mandrel 620 at the first end 602. The 630 coupling is then threaded and attached to the housing connector 614, which is threadably connected to the internal mandrel 610 to prevent a relative rotational movement between the internal mandrel 610 and the coupling 630. A first torque screw is shown at 632 to secure the coupling to the connector. box 614.

[00151] In one aspect, a NACA (National Advisory Committee for Aeronautics) 634 key is also employed. The NACA 634 wrench is placed inside the 630 coupling, and external to a 614 threaded housing connector. A first torque screw is provided at 632, connecting the 630 coupling to the NACA 634 wrench and then to the 614 housing connector. second torque screw is provided at 636 connecting the coupling 630 to the NACA 634 key. NACA shaped keys can (a) secure coupling 630 to the internal mandrel 610 through housing connector 614, (b) prevent coupling 630 from rotating around the inner mandrel 610, and (c) optimize the flow of slurry along the annular space 612 to reduce friction.

[00152] Within the plug 600, the annular space 625 around the inner mandrel 610 is isolated from the main hole 605. In addition, the annular space 625 is isolated from an annular space surrounding the well hole (not shown). The annular space 625 allows the transfer of gravel slurry from alternative flow channels (such as bypass tubes 218) through plug 600. Therefore, the annular space 625 becomes the channel (s) of alternative flow (s) to shutter 600.

[00153] In operation, an annular space 612 resides in the first end 602 of the plug 600. The annular space 612 is disposed between the housing connector 614 and the coupling 630. The annular space 612 receives the slurry from the flow channels alternatives of a connected tubular body, and distributes the slurry to the 625 annular space. The tubular body can be, for example, an adjacent sand sieve, a threadless tube, or a zonal isolation device.

[00154] The plug 600 also includes a loading shoulder 626. Loading shoulder 626 is placed near the end of piston mandrel 620 where coupling 630 is connected and sealed. A solid section at the end of the piston mandrel 620 has an inside diameter and an outside diameter. The loading shoulder 626 is placed along the outside diameter. The inner diameter is threaded and is threaded to the inner mandrel 610. At least one alternating flow channel is formed between the inner and outer diameters to connect the flow between the annular space 612 and the annular space 625.

[00155] The loading shoulder 626 provides a load bearing point. During probe operations, a loading collar or harness (not shown) is placed around the loading shoulder 626 to allow the shutter 600 to be lifted and supported by conventional elevators. The loading shoulder 626 is then temporarily used to support the weight of the shutter 600 (and any connected completion devices, such as sand sieve joints already inserted in the well) when placed on the rotating floor of a probe. Then, the load can be transferred from the loading shoulder 626 to a pipe thread connector, such as the housing connector 614, then to the inner mandrel 610 or base pipe 205, which is threaded by the pipe to the pipe connector. box 614.

[00156] The plug 600 also includes a piston housing 640. The piston housing 640 resides around and is substantially concentric to the piston mandrel 620. The plug 600 is configured to cause piston housing 640 to move axially to the long and in relation to piston mandrel 620. Specifically, piston housing 640 is driven by hydrostatic downhole pressure. The piston housing 640 can be composed of multiple connected segments, or together.

[00157] The piston casing 640 is held in position along the piston mandrel 620 during insertion. Piston housing 640 is secured using a release sleeve 710 and a release key 715. Release sleeve 710 and release key 715 prevent translational movement between piston housing 640 and piston chuck 620. The key Freezer 715 penetrates through both piston mandrel 620 and internal mandrel 610.

[00158] Figures 7A and 7B provide enlarged views of the release sleeve 710 and the release key 715 for the shutter 600. The release sleeve 710 and the release key 715 are held in position by a shear pin 720. In Figure 7A , the shear pin 720 was not sheared, and the release sleeve 710 and the release key 715 are held in position along the inner mandrel 610. However, in Figure 7B, the shear pin 720 has been sheared, and the sleeve release 710 was translated along an inner surface 608 of inner mandrel 610.

[00159] In each of Figures 7A and 7B, the internal mandrel 610 and the surrounding piston mandrel 620 are seen. In addition, piston casing 640 is seen outside piston mandrel 620. The three tubular bodies representing inner mandrel 610, piston mandrel 620, and piston casing 640 are held together against translational or rotational movement by four release keys 715. Only one of the release keys 715 is seen in Figure 7A; however, four separate keys 715 are radially visible in the cross-sectional view of Figure 6E, described below.

[00160] The release key 715 resides within a keyhole 615. Keyhole 615 extends through inner chuck 610 and piston chuck 620. The release key 715 includes a shoulder 734. Shoulder 734 resides within a shoulder recess 624 in piston mandrel 620. Shoulder recess 624 is large enough to allow shoulder 734 to move radially inward. However, this action is restricted in Figure 7A by the presence of the release sleeve 710.

[00161] Note that the annular space 625 between the internal mandrel 610 and the piston mandrel 620 is not seen in Figure 7A or 7B. This is because the annular space 625 does not extend through the cross-section, or because it is very small. Instead, the annular space 625 employs separate radially spaced channels that preserve the support for the 715 release keys, as best seen in Figure 6E. Otherwise, the large channels that make up the annular space 625 are located away from the material of the internal mandrel 610 that surrounds the keyhole 615.

[00162] At each keyway location, a keyhole 615 is machined through the internal chuck 610. Keyholes 615 are drilled to accommodate the respective keyways 715. If there are four keyways 715, there will be four discrete protrusions circumferentially spaced to significantly reduce annular space 625. The remaining area of annular space 625 between adjacent ridges allows flow in the alternating flow channel 625 to bypass the release key 715.

[00163] The projections are machined as part of the body of the internal mandrel 610. More specifically, the material that constitutes the internal mandrel 610 can be machined to form the projections. Alternatively, the projections can be machined as a separate short release chuck (not shown), which is then threaded to the internal chuck 610. Alternatively, the projections can be a separate spacer between the internal chuck 610 and the chuck. piston 620 by welding or other means.

[00164] It is also noted that in Figure 6A, piston mandrel 620 is shown as an integral body. However, the piston mandrel portion 620 where the keyholes 615 are located can be a separate short release housing. This separate housing is then connected to the main piston mandrel 620.

[00165] Each release key 715 has an opening 732. Similarly, release sleeve 710 has an opening 722. Opening 732 in release key 715 and opening 722 in release sleeve 710 are sized and configured to receive a pin shear. The shear pin is seen at 720. In Figure 7A, the shear pin 720 is held inside openings 732, 722 by the release sleeve 710. However, in Figure 7B, the shear pin 720 has been sheared, and only one small portion of pin 720 remains visible.

[00166] An outer edge of the 715 keyway has a wrinkled surface, or teeth. The teeth for the release key 715 are shown in 736. The teeth 736 for the release key 715 are angled and configured to fit a reciprocal wrinkled surface within the piston housing 640. The matched wrinkled surface (or teeth) for the housing piston 640 is shown at 646. Teeth 646 reside on an inner face of piston housing 640. When engaged, teeth 736, 646 prevent movement of piston housing 640 in relation to piston chuck 620 or internal chuck 610. Preferably, the matted corrugated surface or teeth 646 resides on the inner face of a separate short external release sleeve, which is then threaded to the piston housing 640.

[00167] Turning now to Figures 6A and 6B, the plug 600 includes a centering member 650. The centering member 650 is actuated by the movement of the piston housing 640. The centering member 650 can be, for example, as described in WO / 2009/071874, entitled “Improved Centraliser.” This application was filed in favor of Petrowell Ltd., and has an international filing date of 28 November 2008. The international application is hereby incorporated in its entirety.

[00168] The plug 600 also includes a sealing element 655. As the centering member 650 is actuated and centralizes the plug 600 inside the surrounding well bore, the piston housing 640 continues to actuate the sealing element 655 as described in document WO / 2007/107773, entitled “Improved Packer” having an international filing date of 22 March 2007. The international application is hereby incorporated in its entirety for reference.

[00169] In Figure 6A, the centering member 650 and the sealing element 655 are in their insertion position. In Figure 6B, the centering member 650 and the connected sealing element 655 were actuated. This means that the piston housing 640 has moved along the piston mandrel 620, causing both the centering member 650 and the sealing element 655 to engage with the surrounding borehole wall.

[00170] An anchoring system as described in WO 2010/084353 can be used to prevent piston shell 640 from moving backwards. This prevents the cupular element 655 from contracting.

[00171] As noted, the movement of piston casing 640 occurs in response to hydrostatic pressure from well-bore fluids, including gravel slurry. At the insertion position of the plug 600 (shown in Figure 6A), the piston housing 640 is held in position by the release sleeve 710 and the associated piston key 715. This position is shown in Figure 7A. In order to adjust the plug 600 (according to Figure 6B), the release sleeve 710 must be moved out of the way of the release key 715 so that the teeth 736 of the release key 715 are no longer engaged with the teeth 646 piston housing 640. This position is shown in Figure 7B.

[00172] To move and release the release sleeve 710, a seating tool is used. An illustrative seating tool is shown at 750 in Figure 7C. The seating tool 750 defines a short cylindrical body 755. Preferably, the seating tool 750 is inserted into the well hole with a wash tube column (not shown). The movement of the wash tube column along the well hole can be controlled on the surface.

[00173] An upper end 752 of the seating tool 750 consists of several radial pincer fingers 760. The pincer fingers 760 contract when subjected to sufficient inward force. In operation, the pincer fingers 760 are attached to a profile 724 formed along the release sleeve 710. The pincer fingers 760 include raised surfaces 762 that match or attach to the profile 724 of the release key 710. Upon engagement, the seating tool 750 is pulled or lifted into the well hole. Then, the seating tool 750 pulls the release sleeve 710 hard enough to cause the shear pins 720 to shear. Once the shear pins 720 are sheared, the release sleeve 710 is free to travel upward along the inner surface 608 of the inner mandrel 610.

[00174] As noted, the seating tool 750 can be inserted into the well hole with a wash tube. The laying tool 750 can simply be a profiled portion of the wash tube body. Preferably, however, the laying tool 750 is a separate tubular body 755 which is threaded to the wash tube. In Figure 7C, a connection tool is provided at 770. The connection tool 770 includes the external threads 775 which serve to connect to a drill string or other insertion tubular formation. The connection tool 770 extends on the body 755 of the seating tool 750. The connection tool 770 can extend along the entire body 755 to connect to the flush tube or other device, or it can connect to internal threads (not seen) inside the body 755 of the seating tool 750.

[00175] Turning to Figures 7A and 7B, the displacement of the release sleeve 710 is limited. In this sense, a first or upper end 726 of the release sleeve 710 stops against the shoulder 606 along the inner surface 608 of the inner mandrel 610. The length of the release sleeve 710 is short enough to allow the release sleeve 710 to release opening 732 in the release key 715. When completely displaced, the release key 715 moves radially inward, pushed by the crinkled profile in the piston housing 640 when a hydrostatic pressure is present.

[00176] The shear of the pin 720 and the movement of the release sleeve 710 also allow the release key 715 to disengage from the piston housing 640. Shoulder recess 624 is dimensioned to allow the shoulder 734 of the release key 715 to detach or disengage from the teeth 646 of the piston shell 640 once the release sleeve 710 is released. Then, a hydrostatic pressure acts on the piston casing 640 to translate it downwards relative to the piston mandrel 620.

[00177] After the shear pins 720 have been sheared, the piston casing 640 is free to slide along an external surface of the piston mandrel 620. To accomplish this, the hydrostatic pressure from the annular space 625 acts on a shoulder 642 in piston housing 640. This is best seen in Figure 6B. The shoulder 642 serves as a thrust bearing surface. A fluid port 628 is provided through piston mandrel 620 to allow fluid to access shoulder 642. Beneficially, fluid port 628 allows pressure greater than hydrostatic pressure to be applied during gravel sealing operations . Pressure is applied to the piston casing 640 to ensure that the plug elements 655 engage the surrounding borehole.

[00178] The shutter 600 also includes a measuring device. As the piston casing 640 travels along piston mandrel 620, a measurement hole 664 regulates the rate at which the piston casing travels along the piston mandrel, thereby slowing down the movement of the piston casing. piston and adjusting the seating speed for the shutter 600.

[00179] To further understand the features of the illustratively mechanically adjusted shutter 600, several additional cross-sectional views are provided. These are seen in Figures 6C, 6D, 6E, and 6F.

[00180] Firstly, Figure 6C is a cross-sectional view of the mechanically adjusted shutter of Figure 6A. A view is taken along line 6C-6C in Figure 6A. The 6C-6C line is taken through one of the torque screws 636. The torque screw 636 connects coupling 630 to the NACA 634 wrench.

[00181] Figure 6D is a cross-sectional view of the mechanically adjusted shutter of Figure 6A. A view is taken along line 6D-6D of Figure 6B. the line 6D-6D is taken through another between the torque screws 632. The torque screw 632 connects the coupling 630 to the housing connector 614, which is threaded to the internal mandrel 610.

[00182] Figure 6E is a cross-sectional view of the mechanically adjusted shutter 600 of Figure 6A. A view is taken along line 6E-6E of Figure 6A. Line 6E-E is taken through the release key 715. It can be seen that the release key 715 passes through the piston mandrel 620 and the internal mandrel 610. It is also observed that the alternating flow channel 625 resides between the keys bookshelves 715.

[00183] Figure 6F is a cross-sectional view of the mechanically adjusted shutter 600 of Figure 6A. A view is taken along line 6F-6F in Figure 6B. Line 6F-6F is taken along fluid ports 628 within piston mandrel 620. As fluid moves through fluid ports 628 and pushes shoulder 642 of piston casing 640 away from ports 628 , an annular gap 672 is created and elongated between piston mandrel 620 and piston casing 640.

[00184] Coupling the sand control devices 200 to a shutter assembly 300 requires alignment of the bypass tubes 318 in the shutter assembly 300 with the bypass tubes 218 along the sand control devices 200. In this sense, the flow path of bypass tubes 218 in the sand control devices must be interrupted when engaging a shutter. Figure 4A (described above) shows the sand control devices 200 connected to an intermediate plug assembly 300, with the bypass tubes 218, 318 in alignment. However, making this connection typically requires a special sub or bridge tube with a union type connection, a synchronized connection to align the multiple tubes, or a cylindrical liner plate over the connection tubes. These connections are expensive, time-consuming, and / or difficult to handle on the probe floor.

[00185] U.S. Patent No. 7,661,476, entitled "Gravel Packing Methods," describes a production column (referred to as a joint assembly) that employs one or more sand sieve joints. The sand sieve joints are placed between a "load sleeve assembly" and a "torque sleeve assembly." The load sleeve assembly defines an elongated body comprising an outer wall (which serves as an outer diameter) and an inner wall (providing an inner diameter). The inner wall forms a hole through the loading sleeve assembly. Similarly, the torque sleeve assembly defines an elongated body comprising an outer wall (which serves as an outer diameter) and an inner wall (which provides an inner diameter). The inner wall also forms a hole through the fitting of the torque sleeve.

[00186] The loading sleeve assembly includes at least one transport duct and at least one packaging duct. The at least one transport conduit and the at least one packaging conduit are arranged external to the inner diameter and internal to the outer diameter. Similarly, the torque sleeve assembly includes at least one conduit. The at least one conduit is also arranged outside the inner diameter and inside the outer diameter.

[00187] The load sleeve assembly and the torque sleeve assembly can be used to connect a production column to a joint of a sand sieve. The production column includes a “main body portion” that is placed in fluid communication with the sand sieve base tube through the load sleeve assembly and the torque sleeve assembly. The load sleeve assembly and the torque sleeve assembly are constituted or coupled to the base tube in such a way that the transport and packaging ducts are in fluid communication, thus providing alternative flow channels for gravel slurry.

[00188] A coupling assembly can also be used to connect the load sleeve assembly to a sand sieve joint. The coupling assembly has a piping region, in which the piping region is configured so that it is in fluid communication with at least one transport conduit and at least one packaging conduit of the load sleeve assembly for at least a portion gravel sealing operations. The benefits of the load sleeve assembly, the torque sleeve assembly, and the coupling assembly are that they allow a series of sand sieve joints to be connected and inserted into the well bore faster and less expensive. .

[00189] The loading glove and torque glove of U.S. Patent No. 7,661,476 assume that the sand sieve and plug being joined have a compatible radial center. This means that the borehole tools being inserted into the borehole have concentric flow paths, or have eccentric flow paths, and the flow paths correspond. However, it is desirable to be able to fluidly connect borehole tools having different radial center lines. In addition, it is desirable to be able to fluidly connect a first well hole tool having a primary flow path that is concentric to the first tool, with a second well hole tool having a primary flow path that is eccentric to the second tool. Consequently, a connecting joint is provided.

[00190] Figures 8A to 8C demonstrate several eccentric designs for a well bore tool. In this document, illustrative well-hole tools are sand control devices. The sand control devices can be sand screens or tubes without threads. Each well hole tool 800A, 800B, 800C comprises a base tube 810 which defines a hole 805 in it. Hole 805 represents a primary flow path. In addition, each of the 800A and 800C well bore tools comprises a filter medium 820 around the base tube 810. Finally, each of the 800A, 800B, 800C well bore tools includes an alternating flow channel for a gravel slurry. Alternative flow channels in the illustrative sand screens 800A, 800C are rectangular or round bypass tubes; the alternating flow channel in the illustrative threadless tube 800B is an eccentric annular space between the base tube 810 and an outer shell 850.

[00191] In Figure 8A, a first 800A sand control device is shown. The sand control device 800A includes the base tube 810. The filter medium 820 is concentrically arranged around the base tube 810. An external protective cover 840 is then eccentrically placed around the base tube 810 and filter medium 820. The cover 840 is perforated, meaning that it allows the ingress of gravel slurry and well-hole fluids.

[00192] An annular area 835 is formed between the filter medium 820 and the surrounding cover 840. Within the annular area 835 there is a plurality of alternative flow channels. In the arrangement of Figure 8A, these represent transport tubes 830A and seal tubes 832A. The use of transport tubes and sealing tubes as alternative flow channels for gravel slurry is generally known in the art. Transport tubes 830A and sealing tubes 832A reside around filter medium 820.

[00193] In Figure 8B, a threadless 800B tube is shown. The threadless tube 800B again includes the base tube 810. In this arrangement, an outer shell 850 is eccentrically arranged around the base tube 810. An eccentric annular area 835 is formed between the base tube 810 and the surrounding shell 850 serves as the alternating flow channel 830B. The 800B deflected threadless tube is installed above the top joint of a sieve or through an insulated section between the shutters, as known in the art.

[00194] In Figure 8C, a second 800C sand control device is shown. The sand control device 800C again includes the base tube 810. In this arrangement, the filter medium 820 is concentrically arranged around the base tube 810. An external protective cover 840 is then eccentrically placed around the tube base 810 and filter medium 820. The cover 840 is perforated, meaning that it allows the ingress of gravel slurry and well-hole fluids. An annular area 835 is again formed between the filter medium 820 and the surrounding cover 840.

[00195] In Figure 8C, bypass tubes 830C are provided in annular area 835. Bypass tubes 830C serve as alternative flow channels.

[00196] In each of Figures 8A, 8B and 8C, the respective alternative flow channels 830A, 830B, 830C represent the secondary flow paths. These secondary flow paths are eccentric to a radial center of the 800A, 800B, 800C well bore tools. In one embodiment, an eccentric sieve arrangement offers little friction in the secondary flow paths when compared to the bypass tubes in a concentric sieve. It is believed that the use of eccentric sieves in the thumb of a horizontal completion will reduce overall friction or extend the maximum gravel seal length of the completion.

[00197] Figures 9A to 9C demonstrate several concentric designs for a well bore tool. In this document, the illustrative well-hole tools are plugs. Each of the shutters 900A, 900B, 900C comprises a base tube 910 which defines a hole 905 in it. Hole 905 represents a primary flow path. In addition, each of the shutters 900A, 900B, 900C comprises an outer shell 920 around the base tube 910.

[00198] In Figure 9A, a first shutter 900A is shown. The plug 900A includes the base tube 910. The housing 920 is concentric around the base tube 910. An annular area 935 is formed between the base tube 910 and the surrounding housing 920. Optionally, the annular area 935 contains ribs 937 to support and space the housing 920 around the base tube 910.

[00199] The annular area 935 also contains a plurality of alternative flow channels. In the arrangement of Figure 9A, these represent transport tubes 930A and sealing tubes 932A. The use of transport tubes and sealing tubes for alternative flow channels for gravel slurry is generally known in the art.

[00200] In Figure 9B, a second shutter 900B is shown. The plug 900B again includes the base tube 910. The shell 920 is concentric arranged around the base tube 910. An annular area 935 is formed between the base tube 910 and the surrounding shell 920. In this arrangement, no tubes are used transport tubes or sealing tubes; instead, the annular area 935 itself serves as an alternating flow channel 930B.

[00201] In Figure 9C, a third shutter 900C is shown. The plug 900C again includes the base tube 910 and the surrounding housing 920. In this arrangement, the bypass tubes 930C are eccentrically arranged adjacent to the base tube 910. The bypass tubes 830C reside in the annular area 935 and serve as the conduit channels. alternative flows.

[00202] In each of Figures 9A, 9B and 9C, the respective alternative flow channels 930A, 930B, 930C represent the secondary flow paths.

[00203] The series in Figure 8 described above uses sand control devices and a threadless pipe like the illustrative eccentric well hole tools, while the series in Figure 9 uses shutters like the illustrative concentric well hole tools. However, it is understood that any of the series could show a threadless tube having a primary flow path and at least a secondary flow path. In addition, it is understood that the shutters can have an eccentric design, and the sand control devices can have a concentric design. In either case, a connection joint is required that places the primary flow paths in fluid communication and the secondary flow paths in fluid communication.

[00204] Figures 10A to 10C provide cross-sectional views of a connection joint 1000. Connection joint 1000 operates to fluidly connect a first well-hole tool to a second well-hole tool. In Figure 10A, a side view of the connection joint 1000 is shown. It can be seen that the connection joint 1000 defines an elongated tubular body. The connection joint 1000 has a wall 1010. The wall 1010 defines a hole 1005 in it. Hole 1005 serves as a curved primary flow path.

[00205] Wall 1010 has a first end 1012, and a second opposite end 1014. Hole 1005 extends along the length of the joint gasket 1000 from the first end 1012 to the second end 1014. The joint gasket 1000 it also has at least one secondary flow path 1020. Secondary flow path 1020 extends through the body 1010 of the connecting joint 1000, and also extends from the first end 1012 to the second end 1014.

[00206] Figure 10B provides a first cross-sectional view of connection joint 1000. This view is taken along line B-B of Figure 10A. Line B-B is placed at the first end 1012 of the connection joint 1000, which is a pin end. It can be seen from the view in Figure 10B that hole 1005 of connection joint 1000 is eccentric with respect to joint 1000 at the first end 1012. An extension connection member 1030 can be provided to fluidly connect the secondary flow path 1020 to alternate flow channels in a sand sieve or other adjacent borehole tool.

[00207] Figure 10C provides a second cross-sectional view of connection joint 1000. This view is taken along line C-C of Figure 10A. Line C-C is cut through the second end 1014 of the connection joint 1000, which is a box end in Figure 10A, although it can also be a pin end. It can be seen from the view in Figure 10C that the hole 1005 of the connection joint 1000 is concentric with the joint 1000 at the second end 1014.

[00208] In the arrangement of Figures 10A and 10B, the first end 1012 of the connection joint 1000 is designed to threadably connect or provide fluid communication to a well hole tool that is eccentric. This borehole tool may have the profile, for example, of the sand control device 800A in Figure 8A. Therefore, the first end 1012 has an eccentric secondary flow path 1020 which aligns with the rectangular crossing ports (such as the eccentric bypass tubes 830A, 832A of Figure 8A) in the sand sieve.

[00209] Reciprocally, in the arrangement of Figures 10A and 10C, the second end 1014 of the connection joint 1000 is designed to connect in a threadable way or to provide fluid communication to a well hole tool that is concentric. This borehole tool may have the profile, for example, of the 900C plug of Figure 9C. Therefore, the second end 1014 provides a concentric primary flow path 1005 that is connected to a plug, and a secondary flow path 1020 that connects to circular ports (such as bypass tubes 930C of Figure 9C) in the plug.

[00210] Note that the eccentric well hole tool can connect to the first end 1012 of the connection joint 1000 either directly through a connection, or indirectly through the use of a pipe joint. Similarly, the concentric well hole tool can connect to the second end 1014 of the connection joint 1000 either directly through a threaded connection, or indirectly through the use of a coupling and torque sleeve or a sleeve. charge. Examples of a coupling and a torque sleeve or a cargo sleeve are provided in U.S. Patent No. 7,661,476 and U.S. Patent No. 7,938,184.

[00211] It is also noted that the eccentric well hole tool or the concentric well hole tool can be a sand sieve, a plug, or a threadless tube. Each well hole tool is required to have a primary flow path and at least a secondary flow path, in which a radial center of the primary flow path in the first well hole tool is displaced from a radial center of the primary flow path in the second borehole tool.

[00212] The connection joint 1000 itself also has a primary flow path 1005 and a secondary flow path 1020. The secondary flow path 1020 is also curved. Preferably, the secondary flow path 1020 comprises a plurality of bypass tubes or an annular bypass space for conducting a gravel slurry. However, the secondary flow path 1020 can be of any profile.

[00213] In the arrangement of Figure 10B, the secondary flow path 1030 is designed to communicate fluidly at the first end 1012 with the polygonal sealing tubes 830A and transport tubes 832A of Figure 8A. Similarly, in the arrangement of Figure 10C, the secondary flow path 1020 is designed to communicate fluidly at the second end 1014 with the bypass tubes 930C of Figure 9C. However, other fluid communication profiles can be employed either at the first end 1012 or at the second end 1014.

[00214] As noted in the arrangement of Figure 10A, the joint 1000 can contain at least one inflection point along its length, providing an “S” contour. The “S” contour compensates for the displacement of the geometric axis from the eccentric flow paths to the concentric flow paths. A profile or continuous contour with minimal curvature (or “dog leg”) can facilitate the passage of the downhole tool, reduce torque and drag, minimize erosion by particle flow, and minimize flow friction. A typical mathematical description of an “S” contour is a sigmoid function. Examples of sigmoid functions include, without limitation, hyperbolic tangent functions, inverse tangent functions, logistic functions, Rosin-Rammler functions, and erratic functions. Although transit at connection joint 1000 can be as simple as a series of straight lines (without inflection points), a discontinuous profile at the flexion point can represent a high local curvature.

[00215] Figure 11A is a Cartesian graph 1100A that represents the displacement of the geometric axis (first geometric axis y) in relation to the symmetrical length of an illustrative connection joint (geometric axis x). This is for a 4.88 meter (16 foot) joint. The connection joint shown in Figure 1100A in Figure 11A has a profile for a 1.37 cm (0.54 inch) axis offset between eccentric and concentric well hole tools. The displacement of the geometric axis is indicative of curvature. Therefore, line 1110A demonstrates a crossing profile and shows how the center of the hole in a connection joint moves in relation to a longitudinal center line of the tool. As can be seen, a curved or “S” profile is offered.

[00216] Figure 11A also represents the curvature (second y axis) in relation to the symmetrical length (x axis) for the 4.88 meter (16 feet) joint. The curvature is indicative of how sharply the hole in the connection joint rotates at any given location along the center of the hole. In mathematical terms, the curvature is related to those derived from the profile as it reflects the rate of change of direction along the 1110A profile. This rate of change of direction is shown on line 1120A. Note that at the 0-inch mark along the x-axis, the hole has an inflection point.

[00217] The curvature 1120A, or profile, is based on a hyperbolic tangent function. The 1120A curvature is represented by a common unit in the oil field grade by 30.5 meters (100 feet). The example in Figure 11A indicates a maximum of 9 ° / 30.5 meters (100 feet) of curvature over the crossing length of 192 inches (16 feet). The curvature 1120A is equal to zero in the middle of the intersection, or the inflection point.

[00218] The crossing length can be halved to 244 cm (96 inches). This is shown in Figure 11 B.

[00219] Figure 11 B is a Cartesian graph 1100B that represents the displacement of the geometric axis (first geometric axis y) in relation to the symmetrical length of another illustrative connection joint (geometric axis x). This is for a 2.44 meter (8 ft) connection joint. Line 1110B demonstrates a crossing profile for the 244 cm (96 inch) joint, showing how the center of the joint hole moves in relation to a longitudinal center line of the tool. As can be seen, a curved profile is offered again.

[00220] Figure 11 B also represents the curvature (second y axis) in relation to the symmetrical length of a connection joint (geometric axis x) for the 2.44 meter (8 feet) connection joint. Line 1120B demonstrates the curvature of the connection joint hole. In this document, the maximum curvature is quadrupled to 36 ° / 30.5 meters (100 feet).

[00221] As noted earlier, a series of straight lines can be used instead of a curved profile. When a simplified geometry such as straight segments is used, the crossing length can be further reduced, however, the curvature at the bending points (discontinuous) becomes high. Therefore, the crossing design must be balanced between length and curvature.

[00222] Figure 11C is a Cartesian graph 1100C that represents the displacement of the geometric axis (geometric axis y) in relation to the symmetrical length of a connection joint (geometric axis x). This also serves for a 2.44 meter (8 ft) connection joint. In the present document, the 1100C graph compares how the center of the hole of a connection joint moves in relation to a longitudinal center line of the tool or two different hole profiles. Line 1110B is the same as line 1110B in Figure 11 B. Again, this served for a curved profile. Line 1115 is provided to show a profile having straight segments.

[00223] The displacement of the geometry axis and curvature of a 1000 joint are important considerations. The primary flow path of the connection joint 1000 must be able to accommodate the movement of a tool, such as the laying tool 750 of Figure 7C through hole 1005. It can be seen that the amplitude of curvature shown in line 1120A in Figure 11A has a smaller amplitude than the amplitude of curvature shown on line 1120B in Figure 11 B. This is to be expected since the connection joint of Figure 11A is twice the length of the connection joint of Figure 11 B, reducing, thus, the “rate of change of direction” for the curvature.

[00224] Another way to mitigate the impact of curvature on the primary flow path is to increase the internal diameter of the connection joint. The increased diameter facilitates the insertion of other tools down the well through the curved connection joint.

[00225] When using a connection joint, other design options can be considered. For example, when the secondary flow paths serve as alternative flow channels for gravel sealing, a high differential pressure can occur between the secondary flow paths and the primary flow path. In addition, a high differential pressure can occur between the secondary flow paths and the annular space between the connecting joint and the surrounding borehole, that is, the annular space of the borehole. For example, a differential pressure of 6,500 psi near the heel is expected when gravel sealing a horizontal completion interval of 1520 meters (5,000 feet). In order to maintain mechanical integrity (that is, remain within the burst, bend, and collapse classifications) of the secondary flow paths, a certain surrounding wall thickness is required. This in turn limits the internal diameter of the connection joint.

[00226] Other considerations include minimizing the length, providing an overall outside diameter that is less than or equal to the diameters of the adjacent bore tools, maximizing the inside diameter of the primary flow path, and providing an overall mechanical integrity that is equal to or greater than that of the adjacent tools.

[00227] Figure 12 is a flow chart showing the steps of a 1200 method to complete a well hole in a subsurface formation, in one modality. Method 1200 is applicable for the installation of borehole tools having non-aligned flow paths.

[00228] In one aspect, method 1200 comprises firstly providing a first well bore tool. This is shown in Box 1210. The first borehole tool has a primary flow path and at least a secondary flow path. The first borehole tool can be a sand sieve, a plug, or a threadless tube.

[00229] Method 1200 also includes providing a second well bore tool. This is indicated in Box 1220. The second well hole tool also has a primary flow path and at least a secondary flow path. The second well bore tool can be a sand sieve, a plug, or a threadless tube. However, a radial center of the primary flow path of the first well hole tool is displaced from a radial center of the primary flow path to the second well hole tool.

[00230] Method 1200 also includes providing a connection joint. This is shown in Box 1230. The connection joint also comprises a primary flow path and at least one secondary flow path. Then method 1200 includes fluidly connecting the connection joint to the first well hole tool and a first end, and fluidly connecting the connection joint to the second well hole tool at a second end. These steps are provided in Boxes 1240 and 1250, respectively. In this way, the primary flow path of the first well hole tool is in fluid communication with the primary flow path of the second well hole tool. In addition, at least one secondary flow path of the first well hole tool is in fluid communication with at least one secondary flow path of the second well hole tool.

[00231] Method 1200 also includes inserting the connection joint and the first and second well bore tools connected to a well bore. This is seen in Box 1260. The connection joint is inserted to a selected subsurface location within the well hole. The fluid is then injected into the well bore. This is shown in Box 1270.

[00232] So method 1200 includes additionally injecting the fluid from the well hole and through the secondary flow paths of the first well hole tool, the connection joint, and the secondary flow paths for the second drilling tool well bore. This is provided in Box 1280.

[00233] The connection joint can be used to connect any two tubular tools having primary flow paths and secondary flow paths, in which a radial center of the primary flow path in the first borehole tool is displaced from a radial center of the primary flow path in the second well bore tool. However, it is preferred that the connection joint is used as part of a sand control system. In this case, the first well-hole tool is preferably a sand sieve, while the second well-hole tool is preferably a mechanically adjusted plug, such as the plug 600 of Figures 6A and 6B.

[00234] In one embodiment, the primary flow path of the first well-hole tool (such as a sand sieve) is eccentric to the first well-hole tool, while the primary flow path of the second well-hole tool (such as a plug) is concentric to the second well hole tool. In this case, a base tube serves as the primary flow path of the sand sieve, while an elongated internal mandrel serves as the primary flow path of the plug. The secondary flow path for the sand sieve consists of bypass tubes that serve as alternative flow channels. The secondary flow path to the plug can consist of bypass tubes or it can be an annular area formed between the inner mandrel and a surrounding movable piston shell. In any case, the alternative flow channels allow a gravel slurry to bypass the sand sieve joint, the connecting joint, and the plug, even after the plug has been placed in the well hole.

[00235] In one aspect, method 1200 also comprises placing the plug in the well hole. In this case, the step of additionally injecting the fluid through the secondary flow paths is carried out after the plug has been seated.

[00236] Figure 13 is a flowchart showing the steps of a 1300 method of fitting a plug into a borehole, in one embodiment. The shutter is designed according to the shutter 600 of Figures 6A and 6B. First, method 1300 includes inserting a seating tool into the internal mandrel of the plug. This is shown in Box 1310.

[00237] The laying tool is advanced beyond the depth of the plug. So method 1300 includes pulling the adjustment to support the well hole. This is seen in Box 1320. The seating tool has pincer fingers or other raised surfaces that hold the release sleeve. As the seating tool is pulled upward through the well hole, the clamp fingers attach to a release sleeve. Pulling the seating tool mechanically moves the release sleeve out of a retained position along the internal plug mandrel. This in turn releases a piston casing in the plug for axial movement.

[00238] So, method 1300 includes communicating the hydrostatic pressure to the piston casing. This is provided in Box 1330. Hydrostatic pressure communication is conducted through one or more flow ports. The flow ports are exposed to well-hole fluids when the release sleeve is moved. The piston housing has a pressure bearing surface that is activated by hydrostatic pressure. This causes an axial movement of the released piston housing, and the sealing element acts successively against the surrounding borehole.

[00239] The preferred mode for using a connection joint offers the following tool sequence:

[00240] eccentric screen -> connection tool -> concentric shutter

[00241] A variation of this sequence is as follows:

[00242] eccentric screen -> connection tool -> concentric shutter -> connection tool -> eccentric screen

[00243] However, the order of the tool connections is not limited to the use of an eccentric sand sieve and a concentric plug. If a concentric shutter is not available, the operator can choose to use the following tool sequence:

[00244] concentric screen -> connection tool -> eccentric shutter -> connection tool -> concentric screen

[00245] Therefore, the connection joint allows a change in the orientation of the base tubes and the eccentric diversion tubes along a series of sand sieves. In this case, two connection joints are required. Preferably, the first connection joint has a concentric housing end and an eccentric pin end. Preferably, the second connection joint has an eccentric housing end and a concentric pin end.

[00246] A certain type of shutter may be really desirable in some circumstances. If, for example, a particular type of plug allows greater hydrostatic pressure or higher degrees of pressure in deviation flow paths, then such a plug can be selected.

[00247] Another tool sequence for use with a connection joint is: concentric screen -> connection tool -> eccentric screen

[00248] The use of concentric screens can be beneficial when sealing gravel over long intervals. Concentric sand sieves can be more robust for sealing gravel over long intervals. For example, the known concentric screens are capable of sealing with 1520 meters (5,000 feet) of gravel, compared to 914 meters (3,000 feet) with commercial eccentric screens. The new connection tool allows the operator to use the cheapest eccentric screens on the thumb or lower pressure side of the gap during gravel sealing operations, and use the concentric screens on the heel or upper pressure side of the gap during drilling operations. gravel sealing. This reduces the overall cost of completion while still achieving a gravel seal goal.

[00249] It may be difficult to purchase more complex concentric sand sieves in quantities necessary for extended horizontal completions. Therefore, the connection joint allows horizontal completion to continue without delay by combining concentric screens with the most readily available eccentric screens. Therefore, the use of connection joints provides flexibility in maintaining and managing the inventory of sand sieves.

[00250] The connection joint also provides flexibility to the operator to use the best screens for a particular interval, or to better perform the shutter for zonal insulation. The operator is not limited by matching the flow paths of the screens with the shutters, and can take advantage of the best borehole tools available for the service.

[00251] The connection joint also allows the operator to be creative with the use of tubes without threads. For example, the connection joint allows the use of concentric round bypass tubes in the pipe joints without threads above the eccentric screens in multi-zone fracture sealing applications. The concentric round bypass tubes allow for higher fluid injection pressures. The connection joint allows fluid connectivity between the eccentric sand sieve joint and the concentric threadless tube.

[00252] As can be seen, a well bore apparatus is provided. The well-bore apparatus can be generally claimed according to the following subparagraphs:

[00253] 1. Well-bore apparatus, comprising: a first well-bore tool having a primary flow path and at least a secondary flow path; a second well hole tool also having a primary flow path and at least one secondary flow path, in which a radial center of the primary flow path in the first well hole tool is displaced from a radial center of the path primary flow in the second well-hole tool; and a connection joint to connect the first well hole tool to the second well hole tool, the connection joint comprising: a primary flow path that fluidly connects the primary flow path of the first well hole tool the primary flow path of the second well hole tool; and at least one secondary flow path that fluidly connects to at least one secondary flow path of the first well hole tool to at least one secondary flow path of the second well hole tool.

[00254] 2. Well bore apparatus, according to subparagraph 1, in which: the primary flow path in the connection joint is eccentric to the connection joint at a first end; and the primary flow path at the joint is concentric to the joint at a second opposite end.

[00255] 3. Well bore apparatus, according to subparagraph 2, in which the primary flow path at the connection joint has a profile of a sigmoid function.

[00256] 4. Well bore apparatus, according to subparagraph 2, in which the primary flow path in the connection joint comprises at least two linear segments.

[00257] 5. Well bore apparatus, according to subparagraph 1 or subparagraph 2, in which: the well bore apparatus is a sand control device; the first borehole tool is a sand sieve comprising an elongated base tube, a circumferentially filtering medium around the base tube, and at least one bypass tube along the base tube that serves as a channel alternating flow, the at least one bypass tube being configured to allow the gravel slurry to at least partially bypass the first borehole tool during a gravel seal operation in a borehole; the base tube serves as the primary flow path of the sand sieve; and the at least one bypass tube serves as at least one secondary flow path of the sand sieve.

[00258] 6. Well bore apparatus, according to subparagraph 5, in which: the at least one bypass tube is internal to the filtration medium, or external to the filtration medium.

[00259] 7. Well bore apparatus, according to subparagraph 6, in which: each at least one bypass tube has a round profile, a square profile, or a rectangular profile; and the elongated base tube is eccentric to the sand sieve.

[00260] 8. Well-bore apparatus, according to subparagraph 7, in which the first well-bore tool also comprises an external protection cover perforated around at least one bypass tube.

[00261] 9. Well bore apparatus, according to subparagraph 1 or subparagraph 2, in which: the second well bore tool is a plug, the plug comprising an elongated internal mandrel, an external sealing element to the inner mandrel, and an annular region that serves as an alternating flow channel, the annular region being configured to allow the gravel slurry to at least partially bypass the second well hole tool during a gravel sealing operation in a well hole after the plug has been seated in the well hole; the internal mandrel serves as the primary flow path of the plug; and the annular region serves as at least one secondary flow path of the plug.

[00262] 10. Well bore apparatus, according to subparagraph 9, in which the internal mandrel is concentric to the plug.

[00263] 11. Well bore apparatus, according to subparagraph 9, in which the primary flow path has a profile of a sigmoid function.

[00264] 12. Well-bore apparatus, according to subparagraph 1 or sub-paragraph 2, in which: the first well-bore tool is a threadless tube comprising an elongated base tube and at least one bypass tube along the base tube that serves as an alternating flow channel, the at least one bypass tube being configured to allow the gravel slurry to at least partially bypass the first well hole tool during a sealing operation by gravel in a well hole; the base tube serves as the primary flow path of the threadless tube; and the at least one bypass tube serves as at least one secondary flow path of the tube without threads.

[00265] 13. Well bore apparatus, according to subparagraph 5, in which: the second well bore tool is a plug, the plug comprising an elongated internal mandrel, an external sealing element to the internal mandrel , and an annular region that serves as an alternating flow channel, the annular region being configured to allow the gravel slurry to at least partially bypass the second well hole tool during the gravel seal operation in a borehole well after the plug has been seated in the well hole; the internal mandrel serves as the primary flow path of the plug; and the annular region serves as at least one secondary flow path of the plug.

[00266] 14. Well bore apparatus, according to subparagraph 13, in which: the elongated base tube of the sand sieve is eccentric to the sand sieve; and the internal mandrel of the plug is concentric to the plug.

[00267] 15. Well bore apparatus, according to subparagraph 5, in which: the second well bore tool is also a sand sieve comprising an elongated base tube, a circumferentially filtering medium around the base tube, and at least one bypass tube along the base tube that serves as an alternating flow channel, the at least one bypass tube being configured to allow the gravel slurry to at least partially circumvent the second well hole tool during gravel sealing operation in a well hole; the elongated base tube of the sand sieve representing the first borehole tool is concentric to the sand sieve; and the elongated base tube of the sand sieve representing the second well bore tool is eccentric to the sand sieve.

[00268] Although it is apparent that the inventions described here are well calculated to achieve the benefits and advantages presented above, it will be assessed that the inventions are susceptible to modifications, variations and alterations without departing from the spirit of the same. Improved methods are provided to complete an open well bore, which use a connection tool to fluidly connect an eccentric flow path to a concentric flow path.

Claims (13)

1. Connecting joint (1000) to connect a first borehole tool to a second borehole tool, the first borehole tool having a primary flow path and at least a secondary flow path, and the second well bore tool has a primary flow path and at least one secondary flow path, the (1000) joint characterized by the fact that it comprises: a first end to connect the first well hole tool and a second end to connect the second well hole tool; a primary flow path (1005) configured to fluidly connect the primary flow path of the first well bore tool to the primary flow path of the second well bore tool; and at least one secondary flow path (1020) configured to fluidly connect at least one secondary flow path of the first well hole tool to at least one secondary flow path of the second well hole tool, in which a center radial path of the primary flow path in the first well hole tool in a connection to the first end of the connection joint is displaced from a radial center of the primary flow path in the second well hole tool in a connection to the second end of the connection joint; and wherein the primary flow path (1005) at the connection joint (1000) is eccentric to the connection joint at a first end (1012); and the primary flow path (1005) at the connection joint (1000) is concentric to the connection joint (1000) at a second end (1014). 2. Connection joint (1000) according to claim 1, characterized by the fact that the primary flow path (1005) in the connection joint has a profile of a sigmoid function. Connection joint (1000) according to claim 1, characterized by the fact that the primary flow path (1005) in the connection joint (1000) changes the direction along a longitudinal geometric axis of the connection joint ( 1000) at least once. 4. Connection joint (1000) according to claim 3, characterized in that the primary flow path in the connection joint comprises at least two sigmoid segments. Connection joint (1000) according to claim 3, characterized in that the at least one secondary flow path (1020) of the connection joint (1000) changes the direction along a longitudinal geometric axis of the connection joint (1000) at least once. 6. Well-bore apparatus, characterized by the fact that it comprises: a first well-bore tool having a primary flow path (1005) and at least a secondary flow path; a second well bore tool also having a primary flow path and at least a secondary flow path; and a connection joint (1000) for connecting the first well hole tool to the second well hole tool, the connection joint (1000) comprising: a first end for connecting the first well hole tool and a second end to connect the second well hole tool; a primary flow path that fluidly connects the primary flow path of the first well bore tool to the primary flow path of the second well bore tool; and at least one secondary flow path that fluidly connects to at least one secondary flow path of the first well bore tool to at least one secondary flow path of the second well bore tool; wherein a radial center of the primary flow path in the first well hole tool at a connection from the second end of the first well hole tool to the first end of the connecting joint (1000) is displaced from a radial center of the path primary flow in the second well bore tool in a connection from the first end of the second well bore tool to the second end of the connecting joint (1000); and where the primary flow path for the first well hole tool at the second end of the first well hole tool is concentric with respect to a radial center of the first well hole tool and the primary flow path of the second tool of borehole at the first end of the second borehole tool is eccentric with respect to the radial center of the second borehole tool. 7. Well bore apparatus according to claim 6, characterized in that the at least one secondary flow path of the first well bore tool is eccentric to the first well bore tool. 8. Well bore apparatus, according to claim 6, characterized by the fact that: the well bore apparatus is a sand control device; the first well-bore tool is a sand sieve (800) comprising an elongated base tube, a filter medium (820) circumferentially around the base tube, and at least one bypass tube (830) along the base tube (810) which serves as an alternating flow channel, the at least one bypass tube being configured to allow the gravel slurry to at least partially bypass the first borehole tool during the drilling operation gravel sealing in a well hole; the base tube (810) serves as the primary flow path of the sand sieve (800); and the at least one bypass tube serves as at least one secondary flow path of the sand sieve. 9. Well-bore apparatus according to claim 8, characterized by the fact that: at least one bypass tube (830) is internal to the filtration medium (820). 10. Well-bore apparatus according to claim 8, characterized by the fact that: at least one bypass tube is external to the filtration medium (820). 11. Well bore apparatus according to claim 10, characterized by the fact that: at least one bypass tube (830) has a round profile, a square profile, or a rectangular profile; and the elongated base tube (810) is eccentric to the sand sieve (800). 12. Well-bore apparatus according to claim 11, characterized in that the first well-bore tool further comprises an external perforated protective cover (840) around at least one bypass tube. 13. Well bore apparatus according to claim 6, characterized by the fact that: the second well bore tool is a plug (900), the plug comprising an elongated internal mandrel (910), an element of sealing external to the internal mandrel (910), and an annular region (935) that serves as an alternating flow channel, the annular region being configured to allow the gravel slurry to at least partially circumvent the second drilling tool well during gravel sealing operation in a well hole after the plug (900) has been placed in the well hole; the internal mandrel (910) serves as the primary flow path of the plug (900); and the annular region (935) serves as at least one secondary flow path of the plug (900).

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